Bitumen (colloquially known as “tar” due to its similar appearance, odor, and color) is a thick, sticky form of crude oil, so heavy and viscous (thick) that it will not flow unless heated or diluted with lighter hydrocarbons. Bituminous sands—colloquially known as oil sands (or tar sands)—contain naturally occurring mixtures of sand, clay, water, and bitumen and are found in extremely large quantities in Canada and Venezuela.
Conventional crude oil is normally extracted from the ground by drilling oil wells into a petroleum reservoir, allowing oil to flow into them under natural reservoir pressures, although artificial lift and techniques such as water flooding and gas injection are usually required to maintain production as reservoir pressure drops toward the end of a field's life. Because extra-heavy oil and bitumen flow very slowly, if at all, under normal reservoir conditions, oil sands must be extracted by strip mining or the oil made to flow into wells by in situ techniques that reduce the viscosity. Viscosity can be reduced by injecting steam, solvents, and/or hot air into the sands or by in situ combustion. Such processes can use more water and require larger amounts of energy than conventional oil extraction, although many conventional oil fields also require large amounts of water and energy to achieve good rates of production.
The use of steam injection to recover heavy oil has been in use in the oil fields of California since the 1950s. In Cyclic Steam Stimulation (“CSS”) or “huff-and-puff” the well is put through cycles of steam injection, soak, and oil production. First, steam is injected into a well at a temperature of 300 to 340 degrees Celsius for a period of weeks to months. The well is then allowed to sit for days to weeks to allow heat to soak into the formation. Later, the hot oil is pumped out of the well, again for a period of weeks or months. Once the production rate falls off, the well is put through another cycle of injection, soak and production. This process is repeated until the cost of injecting steam becomes higher than the money made from producing the oil. The CSS method has the advantage that recovery factors are around 20 to 25% and the disadvantage that the cost to inject steam is high.
Steam Assisted Gravity Drainage (SAGD) is another enhanced oil recovery technology that was developed in the 1980s and fortuitously coincided with improvements in directional drilling technology that made it quick and inexpensive to do by the mid 1990s. In the SAGD process, two parallel horizontal oil wells are drilled in the formation, one about 4 to 6 meters above the other. Steam is injected into the upper well, possibly mixed with solvents, and the lower one collects the heated crude oil or bitumen that flows out of the formation, along with any water from the condensation of injected steam.
The basis of the SAGD process is that the injected steam forms a “steam chamber” that grows vertically and horizontally in the formation. The heat from the steam reduces the viscosity of the heavy crude oil or bitumen, which allows it to gravity drain into the lower wellbore. The steam and gases rise because of their low density compared to the heavy crude oil below, ensuring that steam is not produced at the lower production well.
The gases released, which include methane, carbon dioxide, and usually some hydrogen sulfide, tend to rise in the steam chamber, filling the void space left by the oil and, to a certain extent, forming an insulating heat blanket above the steam. The condensed water and crude oil or bitumen gravity drains to the lower production well and is recovered to the surface by pumps, such as progressive cavity pumps, that work well for moving high-viscosity fluids with suspended solids.
Operating the injection and production wells at approximately reservoir pressure eliminates the instability problems that plague all high-pressure steam processes and SAGD produces a smooth, even production that can be as high as 70% to 80% of oil in place in suitable reservoirs. The process is relatively insensitive to shale streaks and other vertical barriers to steam and fluid flow because, as the rock is heated, differential thermal expansion causes fractures in it, allowing steam and fluids to flow through. This allows recovery rates of 60% to 70% of oil in place, even in formations with many thin shale barriers.
Thermally, SAGD is twice as efficient as the older CSS process, and it results in far fewer wells being damaged by high pressure. Combined with the higher oil recovery rates achieved, this means that SAGD is much more economic than pressure-driven steam processes where the reservoir is reasonably thick.
Although having certain advantages, oil production techniques like SAGD and CSS also typically produce significant amounts of carbon dioxide. In an era of increasing concern over CO2 production and global warming, methods of reducing the CO2 footprint are thus desirable. Additionally, heat losses to over and under burdens have negative impact on economics or may even limit the applicability of thermal recovery processes. The heat loss problem is seldom directly dealt with and often shunned by resorting to a less effective and more time-consuming non-thermal recovery process.
Capturing and sequestering CO2 in a geologic formation has been proposed to reduce the CO2 emission that contributes to global warming. Additionally, co-injecting CO2 and steam in oil wells to mobilize the heavy oil has been proposed. However, existing methodologies use CO2 at or near the production well, which has disadvantages. First, CO2 partial pressure will detrimentally affect the saturation temperature of the injected stream. Second, CO2 as a non-condensable gas can provide some insulation and reduce heat loss to surroundings. However, when co-injected with steam, it tends to stay ahead of the steam chamber and hence limits the development of steam chamber.
Thus, what is needed in the art are better, more cost effective ways of improving oil recovery, and at the same time allowing sequestration of CO2.